The processing and interpretation of seismic data to define the earth's subsurface has long been used in locating oil and gas reserves and determining optimum locations for drilling. Seismic data is accumulated by well known methods. Typically, seismic receivers or geophones are laid out along a seismic line at spaced intervals from a shotpoint which sends a wave of seismic energy into the earth. The energy generated by the source penetrates the layers of material in the subsurface of the area of interest, propagating at different speeds through different types of formations. As a result of reflections, refractions and diffractions occurring at each layer of material encountered, secondary seismic energy is returned to the surface. The secondary energy signals are detected by the geophones which generate electrical signals representative of the amplitude of the secondary seismic energy. The sensor array is then moved along the line to a new position and the process is repeated, ultimately resulting in data from a large number of closely spaced geophone locations. The same basic approach is utilized in offshore exploration as well as on land.
The signals generated by the geophones are processed in the field or at a later time in a data processing center to remove noise and extraneous signals so that only reflected signals remain, and the amplitude of the signals from each geophone is continuously recorded against time to produce seismograms. In order to eventually create a depth profile of the various layers or horizons of interest the reflected ray traces between the shotpoint and each geophone must be grouped and compared. The conventional way of doing this is to assume that a point halfway between the shotpoint and a receiver overlies the point on the subsurface layer of interest from which the reflection came. This point is known as the common mid point (CMP) or the common depth point (CDP). Traces are binned according to the CDP and are summed or stacked for purposes of data interpretation. According to the CDP theory it is assumed that the time it takes for the primary energy from the shotpoint to reach the horizon is equal to the time for the reflected energy to reach the receiver. Thus by determining the distance traveled by the energy wave in half the time between the instant of the shot and the signals generated by a receiver, the depth of the horizon of interest can be determined.
This underlying theory is known to be incorrect in all but those cases in which the horizon is horizontal. If the horizon dips the reflection point on the horizon will not be directly beneath the CDP but will be offset from it, which means that the time for the primary energy wave to reach the reflection point is greater or less than the time for the secondary energy to reach the receiver. To compensate for these intrinsic errors corrections to the data are performed. Thus normal moveout corrections, which convert each receiver output to the output it would have produced if the source and receiver had been located at the CDP, and dip moveout corrections, which account for the slope of the relevant horizon, are carried out. These corrections, which involve the shifting in time of the reflected events of the traces, are still not able, however, to overcome the basic errors inherent in the CDP theory in areas of steep dip. Such errors can produce final mapping errors of considerable significance, the magnitude of which can readily be greater than a mile or more.
In areas of steep dip, such as in the vicinity of salt domes where both the dip and the dip direction of seismic reflectors change rapidly over a short distance, it is desirable to use depth processing in order to provide a three-dimensional image of the substructure. This requires that the area of the reflected energy be located in all three spatial dimensions. One way of accomplishing this is to lay out the seismic lines along grids and then shoot and process the data, using three-dimensional time migration. There are problems, however, in utilizing this method. In practice, the location of the source and receivers must be accurately known. Otherwise, the quality of the resulting seismic images can be seriously degraded. Further, errors in location can readily result from surveying errors, processing errors, bookkeeping errors, and communication errors between the shooter and the observer as to the source being initiated. In addition, even when the program is run correctly, it requires a great deal of time compared to a simpler two-dimensional program run along one or several seismic lines.
Another way of locating the reflected energy in all three spatial directions is to use data from two-dimensional seismic lines and apply time migration corrections. This still does not take into account energy recorded from reflections originating out of the vertical plane of the seismic line, as would be encountered in an area of steep dips. Moreover, the data is still initially inexact due to the inherent drawbacks of the CDP theory discussed above.
In both systems of producing three-dimensional models the practical limitation of the slope of dips which can be imaged is up to about 60.degree.. Since areas of steeper dips are not uncommon, particularly in the vicinity of salt domes, it would be highly desirable to be able to image steeper dips. Due to the errors introduced by CDP stacks or gathers it would be desirable to be able to produce three-dimensional models which are not based on the CDP traces.